System and process for flue gas processing

ABSTRACT

The present invention is directed to a new and improved method for sequestration of carbon dioxide, the method including the steps of injecting a carbon dioxide-containing injection gas into a subsurface containment region with a series of captures zones; providing sufficient time for said injection gas to at least partially stratify and form constituent gas mixtures which at least partially accumulate in the capture zones; providing a vent associated with one of the capture zones; and, evacuating at least a portion of the constituent mixtures through the associated vent.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority under 35 U.S.C. 119(e) and 37 C.F.R.1.78(a)(4) based upon copending U.S. Provisional Application, Ser. No.61/304,580 for SYSTEM AND PROCESS FOR FLUE GAS PROCESSING, filed Feb.15, 2010, the disclosure of which is incorporated herein by reference.

FIELD OF THE INVENTION

The present invention relates to a system and process for flue gasprocessing, more specifically to a system and process for processing andsequestration of flue gas constituents in subsurface structures. Thepresent invention also relates to a system for using the gas processingto enhance hydrocarbon recovery from low pressure subsurface geologicalformations.

BACKGROUND OF THE INVENTION

Increasing concentrations of greenhouse gases, including carbon dioxide,in the atmosphere are a subject of concern. It is feared that emissionof these gases into the atmosphere could lead to global warming,sea-level changes, and different weather patterns, among otherdetrimental effects. Controlling the release of these gases into theatmosphere is thus an increasingly important concern. Response to thisconcern has lead to governmentally limited prohibitions and restrictionson carbon dioxide emissions, or fees associated with the emissions ofsuch gases. Those approaches lead to high economic costs for industriesthat emit green house gases, especially those that emit flue gases intothe atmosphere.

In order to meet past and new emissions standards, several approacheshave been developed to make flue gases cleaner. Some approaches toreduce the emissions of undesired particulates within various gasesinclude using above ground technologies such as adsorption by microporous solids and absorption by chemical solvents. Other approachesinclude the geosequestration of purified gas in underground formations.However, current technologies have not developed systems or processesthat make large scale sequestration of CO₂ financially feasible.

Rather than sequestering the CO₂, which currently is not financiallyfeasible for most large-scale operations, some methods utilize it inpurified form to enhance oil recovery from underground formations.However, using purified CO₂ for this purpose also presents a number ofproblems for the producer of the well. In most large-scale enhanced oilrecovery operations utilizing purified CO₂, the primary cost of therecovery is the purchase of CO₂, which may represent operating costs asmuch as 68% of the total cost of the revenue from the project. The costof acquiring purified CO₂ in large quantities is driven by the very highcost of separation of CO₂ from flue gases and its subsequenttransportation to the sequestration site where it can then be injectedinto the subsurface formation. Moreover, the relative cost of largescale CO₂ capture, injection, and sequestration increases as oil pricesdecline.

Traditional configurations for hydrocarbon recovery processes requiresubterranean depths of greater than eight hundred meters, with asufficient trapping mechanism and sufficiently porous geological textureto handle large volumes of injected gases. Different trapping mechanismsoccur which vary depending on the associated structure and desiredduration of the sequestration. In addition, traditional configurationsrequire subsurface containment regions capable of receiving high flowinjection rates under very high injection pressures to sustain CO₂sequestration. Using the present invention, CO₂ sequestration isachievable at relatively shallower levels with reduced injection flowrates and pressures.

Despite the prior art's predominant usage of purified CO₂ in enhancedrecovery methods, it is also possible to enhance the oil recoveryprocess by using gases of differing compositions, such as those withcompositions similar to common flue gases. Constituents of thesemixtures may be at least partially soluble in hydrocarbons contained inthe underground formation and in many situations the resulting solutionswill experience a more favorable mobility due to decreased viscosity. Inaddition, the resulting low-cost pressurization of the undergroundcontainment region may promote increased recovery.

Moreover, potential sequestration locations for CO₂ injection are seldomlocated in close proximity to coal-fired electric power plants and otherlarge scale flue gas sources. The cost of transporting purified liquidCO₂ by truck or pipeline is considerable. This circumstance exists fornonsequestration commercial markets of CO₂ as well. Therefore, thesignificant costs of carbon capture include the additionally significantcosts of transporting liquefied CO₂ by tanker truck or pipeline. Thecombination of such energy costs and limited commercial demand for CO₂do not make the sale of CO₂ captured by above-ground mechanicaltechnologies commercially viable in many situations. For these reasons,neither sequestration nor the commercial sale of purified CO₂ aregenerally considered sufficient, practical, or financially feasible forutilizing all of the CO₂ contained in flue gases.

Additionally, the capital costs of the equipment necessary forlarge-scale separation and capture of CO₂ from power plant flue gasesare enormous, generally in excess of $1.2 billion per plant.

Furthermore, the cost of large-scale separation and capture of CO₂ fromflue gases has generally been considered commercially prohibitive forwaste disposal due to the enormous volumes of energy required tocondense the gases to the point where liquid CO₂ can be extracted. For acoal-fired electric power plant, estimates are that the energy cost ofCO₂ separation can exceed by 30% to 40% the electricity productioncapacity of the plant. The result of combined capital and energy cost oflarge-scale CO₂ separation and capture from power plant flue gases couldbe very substantial increases in the price of electricity to consumers.Some estimates are that costs to consumers would need to double for themethod of disposal to become commercial viability.

Some prior attempts at utilizing hydrocarbon recovery techniques havebeen described in Screening and Ranking of Hydrocarbon Reservoirs forCO₂ Storage in the Alberta Basin, Canada by Buchu, which is incorporatedby reference.

Heretofore, there exists a need for an improved system and process forhydrocarbon recovery using emission gases sequestered in geologicalstrata.

SUMMARY OF THE INVENTION

The present invention is directed to a method for sequestration ofcarbon dioxide, said method comprising the steps of injecting a carbondioxide-containing injection gas into a subsurface containment region,said containment region further comprising a series of captures zones;providing sufficient time for said injection gas to at least partiallystratify forming constituent gas mixtures and for said constituentmixtures to at least partially accumulate in said capture zones;providing a vent associated with one of said capture zones; and,evacuating at least a portion of one of said constituent mixturesthrough said vent.

DETAILED DESCRIPTION OF THE INVENTION

As required, detailed embodiments of the present invention are disclosedherein; however, it is to be understood that the disclosed embodimentsare merely exemplary of the invention, which may be embodied in variousforms. Therefore, specific structural and functional details disclosedherein are not to be interpreted as limiting, but merely as arepresentative basis for teaching one skilled in the art to variouslyemploy the present invention in virtually any appropriately detailedstructure.

An exemplary embodiment of the system and process for production ofhydrocarbon using the sequestration of carbon dioxide is comprised of aflue gas source, a subsurface containment region, which may include abrine zone, an oil zone, and plural capture zones. The subsurfacecontainment region is in communication with a compression source spacedapart from the subsurface containment region. Additionally, thesubsurface containment region includes a vessel, a formation, or otherstructure which surrounds its perimeter. As illustrated, the flue gasesare injected into the subsurface containment region from the compressionsource and are dispersed throughout. Flue gases associated with a brinezone would permeate through the brine material separating some of theconstituent gases from the flue gas into soluble CO₂ and other insolublegases. As these constituent gases are separated, they are allowed tomigrate. Exemplary processes include the migration of at least a portionof the insoluble gases into a hydrocarbon fluid reservoir, where theadditional soluble CO₂ permeates the fluid hydrocarbons, enhancing thetransport characteristics of the hydrocarbon and thereby enhancing thehydrocarbon production. In other processes, the insoluble CO₂ is allowedto migrate to structurally higher areas of the subsurface containmentregion. Any CO₂ retained in the hydrocarbon zone may be extractedthrough hydrocarbon production, captured at the surface, and reinjectedinto the subsurface containment region for use in various embodiments ofthis invention.

Flue gases from various industrial processes may be utilized in thepresent invention and may be processed prior to introduction into thesubsurface containment region. Alternatively, the present invention mayremove some contaminants from the flue gas through a filtering orseparation processes. Typically, the industrial flue gas may beprocessed during or in association with the industrial process bystrippers or scrubbers.

In one embodiment, the flue gas 14 is processed to remove at least aportion of (1) undesirable particles, (2) sulfur dioxide, (3) nitrousoxides and (4) moisture content. The resulting flue gas may have acomposition that is, for example, 10.73% CO₂, 1.39% CO 0.76% NO_(x),0.03% SO₂, and 87.09% air, although percentages of constituent gases mayvary. The greater the concentration of CO₂, the more desirable the fluegas is for application of this invention. Carbon Capture And Storage(CCS) in Nigeria: Fundamental Science and Potential ImplementationRisks, Galadima & Garba (2008 SWJ Vol 3, No. 2): pgs 95-99; and TheFuture of Carbon Capture and Storage (CCS) in Nigeria, Anastassia etal., (2009 SWJ Vol. 4, No. 3):1-6 which are attached hereto andincorporated by reference.

The composition and proportions of the flue gas and its contaminants mayvary depending on the specific industrial process utilized. If solventabsorption of carbon dioxide is used for the sequestration, andmonoethanolamine is the solvent, reactions with diatomic oxygen, nitrousoxides, and sulfoxides may lead to numerous operational problems such asfoaming, fouling, increased viscosity, and formation of undesirablesalts. Diatomic oxygen concentrations in the range of about 3% to 12% intypical flue gas streams are known to induce oxidative degradation ofalkanolamines, resulting in severe corrosion of associated piping. Thusthe proportion of oxygen should be minimized or oxygen inhibitorsemployed. Additional information on contaminants and flue gas processingis disclosed in Supap, T; Idem, R.; Tontiwachwuthikul, P.; Saiwan, C.Analysis of monoethanolamine and its oxidative degradation productsduring CO₂ absorption from flue gases: A comparative study of GC-MS,HPLC-RID, and CE-DAD analytical techniques and possible optimumcombinations. Industrial & Engineering Chemistry Research, 2006, 45 (8),2437 which is incorporated by reference.

While the invention discloses using flue gas, other CO₂ containing gasesmay be utilized in the present invention. While pressurization ofsubterranean formations may be generally understood, by using a CO₂enriched gas, unexpected benefits may be achieved through the enhancedliquidity of the fluid hydrocarbon as well as a reduction in thepressures necessary to achieve hydrocarbon recovery.

In one embodiment, the flue gases may be injected into the subsurfacecontainment region through a compression source such as an injectionwell extending from the surrounding structure opposite the subsurfacecontainment region into the subsurface containment region. See forexample American Petroleum Institute, 2007, Background Report, “Summaryof Carbon Dioxide Enhanced Oil Recovery (CO₂ EOR) Injection Well eTechnology”, 1220 L Street NW, Washington, DC, attached hereto andincorporated by reference. In addition, various textured surfaces mayenhance the capacity of the subsurface containment region as well asallowing for an increase in the efficiency of the sequestration andhydrocarbon recovery. Some exemplary subsurface containment regions mayinclude depleted oil and gas reservoirs, saline aquifers, coal beds andartificial vessels designed to sustain the hydrocarbon production. Theinjection well, which may be in communication with a production well,would inject the flue gases into the subsurface containment region. Asthe flue gases enter the subsurface containment region, through theprocess described above, the flue gas would separate for immersion ofthe fluid hydrocarbon by the separated soluble CO₂. Optionally, thesubsurface containment region may be sealed from the ambient surfaceenvironment allowing for additional separation of the CO₂ from the fluegas and for additional saturation of the fluid hydrocarbon by solubleportions of the separated CO₂.

The flue gas when initially injected into the subsurface containmentregion is a mixture of constituent gases. Subsequent to the injection,the flue gas stratifies, at least partially, into zones of concentrationof individual constituent gases dispersed throughout the subsurfacecontainment region. Multiple molecular processes contribute to thestratification. Additionally, the proportions of a constituent gas in azone of concentration vary over time depending on the stratifyingmolecular process. The constituent gases have different relativedensities, thus after being injected into the subsurface containmentregion, there is some tendency for the constituent gases to partiallystratify over time. Because CO₂ is about 50% heavier than the averagemolecular weight of other constituent gases in air, those otherconstituent gases will tend to rise relative to the CO₂ resulting in atleast two zones of concentration, with air concentrating above the CO₂.Because gaseous CO₂ is lighter than oil and water, insoluble CO₂ willtend to rise above those oil and water zones.

Other molecular processes that contribute to zones of concentrationinclude but are not limited to adsorption. The adsorption properties ofconstituent gases in relationship to the within the subsurfacecontainment region leads to zones of concentration. For example, if thesubsurface containment region is an abandoned coal seam, affinity foradsorption of carbon dioxide over methane may be exploited to achieve azone of concentration of carbon dioxide. This affinity may result inenhanced production of methane gas form the coal seam. If thesubterranean structure has capillary structure, the differentconstituent gases of the flue gas travel through that capillarystructure at different rates and thus zones of concentration may form.Further disclosure of apparatus and processes in separation of gases inthis environment is in Effect of Heterogeneity in Capillary Pressure onBuoyancy Driven Flow of CO₂, Ehsan Saadatpoor, Steven L. Bryant, KamySepehrnoori, available athttp://www.cpge.utexas.edu/gcs/pubs/buoyancy_driven_flow_slides.pdf,which is incorporated by reference.

Upon stratification, a capture zone is associated with a givenconstituent gas. The constituent gas can then be directed forcontainment, reinjection, or elsewhere in the process. Gas vents, suchas evacuation ducts, are associated with a desired capture zone in orderto direct the contents of the capture zone to another desired location.In the case of a capture zone associated with carbon dioxide, the gasmay be redirected to an injection well for resequestration into anon-capture zone such as a hydrocarbon zone to achieve incrementallyenhanced hydrocarbon recovery. It may also be directed to a system forenhanced hydrocarbon recovery. The evacuation ducts are associated withcapture zones and thus may be placed at varying depths or associatedwith any location where stratification may occur.

After a portion of the CO₂ is sequestered from the flue gas, it maydiffuse through the pores of the subsurface containment regions or theassociated brine and hydrocarbon zones. Saline structures may alsopresent additional characteristics for containing the sequestered CO₂ oran impermeable capping material may be located between the injectionwell and the injected flue gases to seal the injected gases. Theimpermeable cap may include but is not limited to solid, liquid, orgaseous materials which limit undesired migration of sequestered CO₂.

In an alternative embodiment, surface compression may be utilized toinject the flue gas into the subsurface containment region passing atleast one subsurface geological zones comprised of brine, hydrocarbons,a mixture of brine and hydrocarbons, air, soil, or artificialstructures. Generally, “brine” consists of non-potable water and“hydrocarbons” consist of crude oil and/or natural gas. “Miscibility” isthe ability of two or more substances to form a single homogeneous phasewhen mixed in certain proportions. For petroleum reservoirs, miscibilityis the physical condition between two or more fluids that will permitthem to mix in certain proportions without the existence of aninterface. If two fluid phases form after some amount of one fluid isadded to others, the fluids are considered “insoluble” under thoseconditions.

In order to enhance the oil recovery, the carbon dioxide is preferablysoluble with the associated reservoir oil. The solubility of CO₂ andother injected gases depends upon factors such as reservoir temperature,reservoir pressure, injected gas composition, and oil chemicalcomposition. The enhanced recovery processes involve manipulating theseconditions to achieve miscibility between the injected gas and the oil.

The oil reservoir pressure at the start of a conventional CO₂ floodshould be at least 1.38 MPa above the minimum miscibility pressure (MMP)to achieve miscibility between CO₂ and reservoir oil. This means thatthe ratio between reservoir pressure and minimum miscible pressurenormally should be >1. During the enhanced oil recovery (EOR) alsoreferred to as the secondary stage of oil recovery, the typicalsubsurface containment region for EOR may have various degrees ofsuitability, depending on the intrinsic subsurface characteristics andthe chemical composition of the oil mixture. The range of reservoir andfluid properties suitable for CO₂ miscible injection is quite wide;however, exemplary reservoirs should have oil API gravity >27° (lightoils with density <900 kg/m3), oil saturation So >25%, reservoirpressure >7.6 MPa and ideally 1.4 MPa higher than the minimum misciblepressure (MMP) at the time of CO₂ injection. In addition, thecontainment barrier porosity should be greater than 15% withpermeability >1 md. Immiscible CO₂ flooding is much less common;nevertheless it may be applied to heavy and medium oils (10-25° API;900-1000 kg/m3 density) and in-situ viscosities of 100 to 1000 mPa/s(cp).

Some limited studies have shown that, under cyclic immiscible recoveryconditions, gas injection mixtures containing from 10-25% CO₂ haveachieved exceptional oil recovery. More discussion on enhanced oilrecovery results in varying conditions is disclosed in Rivas, O., Embid,S., and Bolivar, F., 1994. Ranking reservoirs for carbon dioxideflooding processes. SPE Paper 23641, SPE Advanced Technology Series, v.2 (Rivas et al., 1994), which is incorporated by reference.

In another alternative embodiment, the flue gas may be injected directlyinto an oil zone or a brine zone of the subsurface containment region,where at least some quantity of CO₂ from a capture zone is employed.Disclosure of sequestration of CO₂ is included in U.S. Pat. App. Nos.20070215350 and 20100000737, which are incorporated by reference.

After sequestering the CO₂ from the flue gases, the sequestered gasesmay be further separated by the Brine Zone, physically, mechanically orchemically through a reaction process such as but not limited to formingcarbonic acid, and then any remaining sequestered gases may betransported to the Oil Zone, where at least some additional quantity ofCO₂ is extracted from the flue gas via a molecular process. Thenon-soluble gases may be separated from the Oil Zone and be transportedfor capture at Zones 1, 2 or 3 depending on the specific configurationand relative density of the separated gases.

Optionally, the extraction of quantities of CO₂ from the flue gasinjected into the brine zone or oil zone may be further increased if thesubsurface containment region is pressurized. The pressurization may beincreased to a point approaching but not equaling the fracture gradientof the subsurface containment region in order to achieve pressures andtemperatures of greater solubility of CO₂ with formation liquids and/orto increase the drive mechanism to enhance the recovery of hydrocarbons.“Fracture gradient,” measured in pounds per square inch per feet depth,is the pressure that if applied to rock or similar object within asubsurface containment region, will cause that rock to physicallyfracture. The subsurface pressure of said subsurface containment regionmay be increased by one or more means such as mechanical compression atthe surface of the injected flue gas, flooding the formation with water,and adding chemical agents to the flue gas and/or to the subsurfacebrine and/or hydrocarbon bearing zones. U.S. Pat. Nos. 6,491,053,7,506,690, 7,341,102, 6,318,468 and 4,744,417 involve processes andapparatus for enhanced hydrocarbon recovery using CO₂ at varyingpressures and is incorporated by reference.

In yet another embodiment, the non-soluble gases that filter through thebrine zone or through the oil zone may be isolated from the ambientenvironment to allow the CO₂ and other gases to separate according totheir relative densities. Because CO₂ is about 50% heavier than air, theair component of the flue gas will tend to rise relative to the CO₂resulting in at least two zones of concentration, with air concentratingabove the CO₂. Because CO₂ is lighter than oil and water, non-solubleCO₂ will tend to rest on top of those zones.

In yet another embodiment, the contents of a capture zone having aconstituent gas other than CO₂ may be directed outside the subsurfacecontainment region into the atmosphere under controlled conditions,making the evacuated capture zones available for receipt of additionalgasses. In this embodiment, at least one vent associated with at leastone of the capture zones and associated with at least one constituentgas is used to extract at least some of the constituent gas through theassociated vent at the desired capture zone.

The nature of CO₂ leakage behavior will depend on properties of thesubterranean structure, primarily its permeability, and on thethermodynamic and transport properties of CO₂ as well as other fluidswith which it may interact in the subsurface. At typical temperature andpressure conditions in the shallow crust (depth <5 km), CO₂ is lessdense than water, and therefore is buoyant in most subsurfaceenvironments. Upward migration of CO₂ will occur whenever appropriatevertical permeability is available. Potential pathways for CO₂ migrationto structurally high areas of subsurface containment regions include (1)migration through porous rock, and (2) migration along faults orfractures. More disclosure on CO₂ migration is in Assessment of the CO₂Sealing Efficiency of Pelitic Rocks: Two-Phase Flow and DiffusiveTransport, paper 536, presented at 7th International Conference onGreenhouse Gas Control Technologies, Vancouver, Canada. Sep. 5-9, 2004;Zweigel, P., E. Lindeberg, A. Moen and D. Wessel-Berg. Towards aMethodology for Top Seal Efficacy Assessment for Underground CO₂Storage, paper 234, presented at 7th International Conference onGreenhouse Gas Control Technologies, Vancouver, Canada. Sep. 5-9, 2004;Gibson-Poole, C. M., R. S. Root, S. C. Lang, J. E. Streit, A. L. Hennig,C. J. Otto and J. Underschultz; Conducting Comprehensive Analyses ofPotential Sites for Geological CO2 Storage, paper 321, presented at 7thInternational Conference on Greenhouse Gas Control Technologies.Vancouver, Canada. Sep. 5-9, 2004; Lindeberg, E. The Quality of a CO₂Repository: What is the Sufficient Retention Time of CO2 StoredUnderground?, in: J. Gale and Y. Kaya (eds.), Greenhouse Gas ControlTechnologies, Elsevier Science, Ltd., Amsterdam, The Netherlands, 2003;and Espie, T. Understanding Risk for the Long-Term Storage of CO₂ inGeologic Formations, paper 42, presented at 7th International Conferenceon Greenhouse Gas Control Technologies. Vancouver, Canada. Sep. 5-9,2004, which are incorporated by reference.

In yet another embodiment, a portion of any CO₂ and other constituentgases not associated with capture zones is captured proximately in theupper portion of the subsurface containment region. The gas compositionis optionally monitored to detect higher proportions of the flue gasconstituent gases and pressure flows. The subsurface containment regionmay be provided with a mechanical body, such as a gas containment layer,disposed near its upper portion. Disclosure of monitoring and gascontainment systems is in U.S. Pat. Nos. 7,448,828 and 5,063,519, whichare incorporated by reference. The contents of the mechanical body arere-injected through secondary compression back into the subsurfacecontainment region under miscible or immiscible conditions, repeatingthe injection process previously described as desired.

In yet another embodiment, the contents of a CO₂ associated capture zoneare directly produced via conventional gas production means. In thisembodiment, at least one vent associated with a CO₂ capture zone withinthe subsurface containment region is used to direct at least some of theconstituent gas through the associated vent. In a further embodiment,the constituent gas directed from a CO₂ associated capture zone isre-injected through secondary compression back into the subsurfacegeological formation under miscible or immiscible conditions usingsecondary compression. Optionally, the gas directed from the CO₂associated capture zone is injected directly into an oil zone.

In yet another embodiment, the injected flue gas may be shut-in for aperiod of time to allow the injected gases to soak in the brine and/orhydrocarbon zones of the subsurface containment region. The injectedflue gas may alternatively be shut-in for a period of time to allow thepartial or complete stratification of flue gases, where the constituentgases stratify according to their relative densities. Each constituentgas is associated with a relative capture zone for release from thesubsurface containment region.

In yet another embodiment, gaseous CO₂ from the flue gas not associatedwith a capture zone or not directed from a capture zone is stored in thesubsurface containment region by sealing its surrounding surface usingknown techniques, such as a containment barrier around the perimeter ofthe subsurface containment region. The containment barrier is composedof material with low gas permeability. The barrier may be composed ofexisting natural material such as caliche, calcrete, silicrete.Alternatively, the containment barrier may be composed of manmadematerial. U.S. Pat. App. No. 20090220303 discloses using containmentbarriers in sequestration and is incorporated by reference.

While the foregoing detailed description has disclosed severalembodiments of the invention, it is to be understood that the abovedescription is illustrative only and not limiting of the disclosedinvention. It will be appreciated that the discussed embodiments andother unmentioned embodiments may be within the scope of the invention.

1. A method for sequestration of carbon dioxide, said method includingthe steps of: injecting a carbon dioxide-containing injection gas into asubsurface containment region having a series of captures zones;providing sufficient time for said injection gas to at least partiallystratify forming constituent gas mixtures and for said constituentmixtures to at least partially accumulate in said capture zones;providing a vent associated with one of said capture zones; and,evacuating at least a portion of one of said constituent mixturesthrough said vent.
 2. The method of claim 1, wherein said injection gasis a flue gas.
 3. The method of claim 1, further comprising acompression source for injecting said injection gas.
 4. The method ofclaim 1, further comprising the step of pressurizing said containmentregion.
 5. The method of claim 1, wherein said evacuated constituentmixture includes carbon dioxide, said method further including the stepof reinjecting said evacuated constituent mixture into said containmentregion.
 6. The method of claim 1, further comprising the step ofenclosing said containment region with a sealing surrounding surface. 7.A method for enhanced recovery of hydrocarbons and sequestration ofcarbon dioxide, said method comprising the steps of: injecting a carbondioxide-containing injection gas into a subsurface containment region,said containment region further comprising a series of captures zonesand being associated with a hydrocarbon-bearing oil zone, whereby atleast a portion of said injection gas contacts said oil zone; providingsufficient time for said injection gas to at least partially stratifyforming constituent gas mixtures and for said constituent mixtures to atleast partially accumulate in said capture zones; providing a ventassociated with one of said capture zones; evacuating at least a portionof one of said constituent mixtures through said vent; and, producingsaid hydrocarbons from said containment region.
 8. The method of claim7, wherein said injection gas is injected into said containment regionunder conditions of miscibility with at least a portion of saidhydrocarbons.
 9. The method of claim 7, further comprising the step ofcapturing carbon dioxide from said produced hydrocarbons.
 10. The methodof claim 9, further comprising the step of reinjecting said capturedcarbon dioxide into said containment region.
 11. The method of claim 7,wherein said injection gas is a flue gas.
 12. The method of claim 7,wherein said injection gas is injected using a compression source. 13.The method of claim 7, further comprising the step of pressurizing saidcontainment region.
 14. The method of claim 7, wherein said evacuatedconstituent mixture further comprises a proportion of carbon dioxide,and said method includes the step of reinjecting said constituentmixture into said containment region.
 15. The method of claim 7, furthercomprising the step of providing a sealing surrounding surface enclosingsaid containment region.